Downhole hydraulic coupling assembly

ABSTRACT

A completions system utilizing a unique hydraulic coupling. The system includes an upper completion stinger configured for coupling to a lower completion tubular. Both the stinger and the tubular are outfitted with hydraulic lines therethrough. Thus, as the stinger is coupled to the tubular, hydraulic lines are also coupled. However, the termination of each line is sealingly covered by a slidable sleeve in advance of attaining the coupling between the stinger and tubular. Therefore, the lines are protected from contamination during potentially significant periods of well deployment that may occur in advance of completed coupling and system installation. Furthermore, the manner of hydraulic coupling between the stinger and tubular reduces the likelihood of damage to the hydraulic lines during the installation process.

PRIORITY CLAIM/CROSS REFERENCE TO RELATED APPLICATION(S)

This Patent Document claims priority under 35 U.S.C. §119 to U.S. Provisional App. Ser. No. 61/294,330, filed on Jan. 12, 2010, and entitled, “Downhole Equipment and Method of Use” incorporated herein by reference in its entirety. This Patent Document also claims priority under 35 U.S.C. §120 to U.S. patent application Ser. No. 12/056,643, filed on Mar. 27, 2008, entitled, “System and Method for Engaging Well Equipment in a Wellbore” and to U.S. patent application Ser. No. 11/850,243, filed on Sep. 5, 2007, entitled, “System and Method for Engaging Completions in a Wellbore”, both of which are also incorporated herein by reference in their entireties.

FIELD

Embodiments described relate to tools and techniques for coupling hydraulic lines to one another. In particular, embodiments of hydraulic line running through walls of downhole tubing segments are detailed.

BACKGROUND

Exploring, drilling and completing hydrocarbon wells are generally complicated, time consuming and ultimately very expensive endeavors. As a result, over the years increased attention has been paid to monitoring and maintaining the health of such wells. Significant premiums are placed on maximizing the total hydrocarbon recovery, recovery rate, and extending the overall life of the well as much as possible. Thus, logging applications for monitoring of well conditions play a significant role in the life of the well. Similarly, significant importance is placed on well intervention applications, such as clean-out techniques which may be utilized to remove debris from the well so as to ensure unobstructed hydrocarbon recovery.

As with monitoring and interventional applications, the initial well design and architecture also plays a significant role in maximizing efficient recovery from the well. For example, most of the well is generally defined by a smooth steel casing that is configured for the rapid uphole transfer of hydrocarbons and other fluids from a formation. However, a buildup of irregular occlusive scale, wax and other debris may occur at the inner surface of the casing or tubing and other architecture restricting flow there-through. Such debris may even form over perforations in the casing, screen, or slotted pipe thereby also hampering hydrocarbon flow into the main borehole of the well from the surrounding formation.

In order to address scale buildup as noted above, a variety of interventional techniques are available. For example, an inexpensive gravity fed wireline technique may be employed wherein chemical cleaners such as hydrochloric acid are delivered to downhole sites of buildup. Alternatively, for more sizeable buildups, particularly of calcium carbonate, barium sulfate and other crystalline scale deposits, less passive techniques may be utilized. These may include the use of explosive percussion, impact bits, and milling. Further, for less hazardous and more complete clean-outs, techniques employing mechanical fluid jetting tools are generally the most common form of interventions. Such tools may be conveyed into the well via coiled tubing and include a head for jetting pressurized fluids, chemicals, solutions, beads, particles, or penetrants toward the well wall in order to fracture and dislodge scale and other debris.

Unfortunately, running interventional applications involves the delivery of footspace eating clean-out equipment to the oilfield and requires that production from the well be halted. So, for example, a day's time and upwards of several hundred thousand dollars may be spent on rig-up, running and disengaging coiled tubing clean-out equipment, not to mention lost production time. Therefore, as alluded to above, the initial well design and architecture may call for the completions structure to be outfitted with hydraulics capable of accommodating a circulating chemical injection system. This is particularly the case where the likelihood of buildup is accounted for up front, as is often the case in deep water wells. Regardless, with such systems in place, a metered amount of chemical mixture, such as the above noted hydrochloric acid mix, may be near continuously circulated downhole from the oilfield surface. That is, an injection line may be run from surface to downhole points of interest for delivery of chemical mix thereat. Upon delivery, the mix may be produced along with the ongoing production of the well. Thus, the need to halt production or run expensive interventions in order to address undesirable buildup is eliminated.

The above noted chemical injection hydraulics may be provided through a production tubing wall or other available structure. However, the production tubing may be provided in segmented form. As each tubing segment is installed, a challenge is presented in physically coupling the segment to a previously installed segment. In a well where the tubing is to accommodate a hydraulic line as noted above, the challenge of coupling the segments is exacerbated by the requirement of ensuring that hydraulic terminations for each of the segments are also mated with one another during the coupling. In this way, a continuous hydraulic line may be incorporated throughout the completed tubing wall. Indeed, even where the tubing is not segmented, its coupling to an open lower completion may involve mating terminations should the lower completion be outfitted with a chemical injection line.

Unfortunately, the mating of hydraulic terminations slows down the installation process. Perhaps more significantly, however, the likelihood of improperly mated hydraulic terminations during installation is substantial. Even though the hydraulic terminations are generally high dollar, robust fittings, they are often damaged during in the installation process. Thus, dollars are lost to replacement of the terminations and even more so to the time lost in the form of the added runs now required for installation or re-installation of the tubing segments with the damaged terminations.

Even more problematic than damaged terminations requiring replacement is the high likelihood of operators being unaware of damaged terminations in the first place. That is to say, improperly connected terminations may not be learned of during the installation process. Thus, where a fully functional hydraulic line is essential to well operations, the results may be catastrophic, particularly where the line is accommodated through well casing as opposed to production tubing. To date, efforts have been directed at aiding segment orientation during installation through the use of certain swivel devices that may improve the likelihood of proper hydraulic termination mating to a degree. However, there remains no manner of guaranteeing that one termination is perfectly aligned with another for mating during installation of completions structure.

SUMMARY

A completions assembly is provided which includes an upper completions stinger for connection to a lower completion tubular. Both the tubular and the stinger are outfitted with hydraulic lines that are configured for coupling to one another as the noted connection between the tubular and stinger. Additionally, the line of the stinger terminates at a seal that is isolated by a first slidable sleeve relative the stinger. Similarly, the line of the tubular terminates at a port that is isolated by a slidable sleeve relative the tubular. Thus, the lines may be protected by the sleeves until the connection is made.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a front view of an embodiment of a completions assembly with hydraulic lines coupled through separate stinger and tubular completion segments.

FIG. 2 is an overview of an oilfield with a well accommodating the completions assembly of FIG. 1 therein.

FIG. 3A is a schematic view of an upper completion stinger with a hydraulic passage covered by a first slidable sleeve and located adjacent a lower completion tubular with a port covered by a second slidable sleeve.

FIG. 3B is a schematic view of the stinger and tubular of FIG. 3A coupling to one another in a manner forcibly shifting the slidable sleeves.

FIG. 3C is a schematic view of the stinger and tubular of FIG. 3B upon completed coupling with the slidable sleeves shifted to allow hydraulic communication between the passage and the port.

FIG. 4 is a schematic view of an embodiment of the stinger and tubular assembly which allows for hydraulic coupling regardless of radial orientation of the seal and port relative to one another.

FIG. 5A is an enlarged sectional view of the upper completion stinger of FIG. 1.

FIG. 5B is an enlarged sectional view of the lower completion tubular of FIG. 1.

FIG. 6 is a flow-chart summarizing an embodiment of installing and utilizing downhole completions equipped with a hydraulic coupling assembly.

DETAILED DESCRIPTION

Embodiments are described with reference to certain downhole completions systems. In particular, a production assembly is detailed throughout with production tubing running through a cased well to a generally uncased production region. However, a variety of different types of completions may utilize hydraulic coupling tools and techniques as detailed herein. Indeed, any downhole segmented tubulars equipped with hydraulics for coupling to one another may take advantage of the embodiments described herein.

As used herein, terms such as “upper completion stinger” or “lower completion tubular” are meant only to distinguish adjacent downhole tubular structures for coupling to one another. So, for example, no particular structural stinger features are meant to be required due to use of the term “stinger”. Further, even the term “upper” is only utilized to distinguish the tubular that is meant for positioning closer to the oilfield surface as measured through the well. That is to say, the term “upper” does not to require that the tubular literally be at a higher elevation than the adjacent tubular. Indeed, in a horizontal well section the upper completion stinger may not be above the lower completion tubular in terms of elevation.

Referring now to FIG. 1, a front view of an embodiment of a completions assembly 100 is shown. The assembly 100 is a segmented tubular structure with a central channel 110 running continuously therethrough. Additionally, hydraulic lines 135, 165 are run through separate stinger 125 and tubular 150 completion segments. Nevertheless, the lines 135, 165 are hydraulically coupled to one another such that continuous hydraulics are also provided. More specifically, physical coupling of the stinger 125 and tubular 150 results in hydraulic coupling of the lines 135, 165 as a passage 130 of the stinger line 135 is hydraulically aligned with a port 160 of the tubular line 165. That is to say, the passage 130 and the port 160 serve as the terminations for the respective lines 135, 165 and, once hydraulically aligned, define a chamber that allows hydraulic communication between the lines 135, 165. Thus, continuous hydraulic communication between the completion segments 125, 150 is now provided.

As noted above, for sake of distinction, the upper tubular is referred to as a stinger 125 and the lower tubular, merely a tubular 150. However, these tubular segments 125, 150 may have a variety of features commonly found in completions assemblies. For example, the stinger 125 may serve as the coupling end of a larger production tubing 210 as depicted in FIG. 2. Thus, collets 140 or other suitable features may be provided for interlocking with the tubular 150. More specifically, notice a slot 142 at the interior of the tubular 150 for reception of the head 141 of a collet 140.

Continuing with reference to FIG. 1, the noted slot 142 is more specifically located at the inner surface of a slidable sleeve 155 of the lower tubular 150. Thus, as the stinger 125 is plugged into the lower tubular 150 it is received by the slidable sleeve 155. As the stinger 125 continues its downward push into the tubular 150, the sleeve 155 is also forced downward. In the embodiment shown, this downward movement of the sleeve 155 is eventually halted by a limiter screw 175 through the body 157 of the lower tubular 150. At this time, the stinger 125 and collets 140 may continue downward to achieve the above noted interlocking with the slot 142 if such has not already been achieved.

Prior to the above described downward movement of the slidable sleeve 155, the port 160 of the lower tubular 150 is sealingly covered by the sleeve 155. However, the noted downward movement of the sleeve 155 eventually exposes the port 160 which in turn achieves hydraulic alignment with the passage 130 as detailed above. Indeed, as detailed further below, another slidable sleeve 300 may be provided for sealingly covering the passage 130 until the noted coupling and hydraulic alignment is achieved (see FIGS. 3A and 5A).

Referring now to FIG. 2, an overview of an oilfield 200 is shown with a well 280 accommodating the completions assembly 100 of FIG. 1 therein. In this embodiment, the well 280 traverses various formation layers 290, 295 eventually reaching an uncased production region 287 with perforations 289 thereat. The upper completion includes production tubing 210 running through a majority of the well 280 which is defined by casing 285. However, upon approaching the production region 287, a production packer 270 is employed to sealingly secure the tubing 210 in place. Furthermore, the tubing 210 may transition into a screened extension 260 for uptake of production from the noted region 287. Note the intake ports 265 of the extension. Often this is referred to as the lower ‘sand face’ completion. A formation isolation valve 275 may also be present above the uncased production region 287 to provide fluid control to the well 280, for example, to aid the installation process.

Following drilling and casing, installation of the completions system depicted in FIG. 2 may involve achieving fluid control as noted and installing or ‘hanging’ the screened extension 260. Subsequent connection of the production tubing 210 to the extension 260 is then followed by setting of the production packer 270 among a variety of other steps. However, in terms of connecting the upper and lower completions, or in this case, connecting the production tubing 210 to the extension 260, a unique form of hydraulic coupling may also be involved. Indeed, the assembly 100 of FIG. 1 is shown serving as the jointed coupling between the production tubing 210 and the extension 260. Thus, the entire system may be equipped with independent hydraulics, apart from the central production channel 110 of the system (see FIG. 1).

With added reference to FIG. 1, separate hydraulic lines 135, 165 may be hydraulically connected at the coupling assembly 100 of FIG. 2. As such, chemical injection or other production aiding fluids may be transferred from the oilfield surface 200 all the way down to the lower completion, the screened extension 260 in this case. Thus, in one embodiment, a scale reducing acid mixture may be ported into the well 280 or production channel 110 at locations prone to such buildup, perhaps particularly directed at the intake ports 265 of the extension 260. Once more, the continuous hydraulics allowing for such chemical injection are installed in a manner that avoids line contamination and substantially reduces the likelihood of damage to the structure of the connecting lines 135, 165 as detailed further below.

Continuing with reference to FIG. 2, the oilfield 200 is depicted accommodating a host of surface equipment 220. A rig 221 is even provided to support other interventional equipment and applications as needed. Further, the production tubing 210 is shown descending from a well head 226 which accommodates a production line 228 for carrying away produced fluids drawn from the production region 287. A control unit 222 is also provided for directing any number of applications. For example, as noted above, the unit 222 may direct and regulate chemical injection through the entire system so as to enhance production. Along these lines, an injection unit 224 is provided adjacent the control unit 222. The injection unit 224 may accommodate and regulate the distribution of a chemical injection mixture through the system as directed by the control unit 222.

Referring now to FIG. 3A, a schematic view of the hydraulic coupling assembly 100 of FIG. 1 is shown. In this case, the upper completion stinger 125 is shown adjacent the lower completion tubular 150 prior to coupling as depicted in FIG. 1. So, for example, with reference to FIG. 2, this would be immediately prior to coupling of the production tubing 210 to the installed extension 260. Notably, at this time, during deployment of the production tubing 210, the passage 130 of the associated stinger 125 is covered by a first slidable sleeve 300 (or the stinger sleeve 300). Thus, contamination of the stinger line 135 with well fluid during deployment is avoided. By the same token, the port 160 of the lower completion tubular 150 associated with the extension 260 is covered by the second slidable sleeve 155 (or the tubular sleeve 155). This is the sleeve 155 which is detailed with reference to FIG. 1 hereinabove. Regardless, contamination of the tubular line 165 with well fluid is again avoided due to the sealed covering provided to the port 160 by the indicated sleeve 155.

Sealingly covering the passage 130 and the port 160 in advance of the coupling of the stinger 125 to the tubular 150 may help to maintain functionality of the hydraulics. For example, the risk of contamination is not limited to altering a particular chemical mixture or other hydraulic fluid. Rather, the contamination could amount to debris and particulate with the capability of impeding or even disabling hydraulic function through the connected lines 135, 165 of FIG. 1. By keeping the noted passage 130 and port 160 sealingly covered in advance of their hydraulic mating, such catastrophic blockage may be avoided.

Referring now to FIG. 3B, a schematic view of the hydraulic coupling assembly 100 of FIG. 1 is again depicted. However, in this case, the upper completion stinger 125 and the lower completion tubular 150 are shown physically coupling to one another. Further, as this coupling begins to take place, the slidable sleeves 300, 155 are forcibly shifted in opposing directions. That is, the first sleeve 300 of the stinger 125 is shifted in an uphole direction whereas the second sleeve 155 of the tubular 150 is shifted in a downhole direction.

It is worth noting that in advance of the passage 130 and the port 160 becoming hydraulically aligned as shown in FIG. 3C, each remains sealingly covered in spite of the shifting of the sleeves 300, 155. That is to say, each sleeve 300, 155 may serve as a conventional dynamic seal continuing to maintain sealing in spite of the shifting.

Referring now to FIG. 3C, yet another schematic view of the hydraulic coupling assembly 100 of FIG. 1 is shown. In this view, the upper completion stinger 125 is now shown fully coupled to the lower completion tubular 150 as in the case of FIG. 1. The passage 130 and port 160 are now hydraulically aligned and uncovered by the slidable sleeves 300, 155. As such, hydraulic communication between the passage 130 and port 160 is now permitted as detailed with reference to FIG. 1 above.

With added reference to FIG. 1, the physically and hydraulically coupled assembly 100 may remain in place for operations such as the noted chemical injection, hydraulic control of downhole tools (even within the production region of FIG. 2), or other applications. However, in other embodiments, the assembly 100 may be configured to allow controlled decoupling of the stinger 125 and tubular 150 following shorter term applications. For example, the stinger 125 may be retracted such that heads 141 of the collets 140 shift the tubular sliding sleeve 155 back into position over the port 160. This upward shift may be controllably halted by the presence of the limiter screw 175, resulting in deflection of the collets 140. The stinger sleeve 300 may similarly be spring loaded or otherwise forcibly biased in a downhole direction. As such, the continued uphole removal of the stinger 125 may proceed with the port 160 and passage 130 sealingly re-covered by the appropriate sleeves 155, 300 (returning to a position such as that of FIG. 3A).

Referring now to FIG. 4, a schematic view of the assembly 100 is shown in which the stinger 125 is equipped with a passage 130 that is circumferential. Indeed, as shown in FIG. 4, the passage 130 is apparent about the perimeter of the stinger 125 and defined by seal rings 400. As a result, no particular radial orientation of the stinger 125 is required in order to attain hydraulic coupling with the tubular 150. Indeed, as depicted in FIG. 4, even though the port 160 of the tubular 150 is located opposite the positioning shown in FIGS. 3A-3C, hydraulic coupling with the passage 130 is nevertheless attained. In fact, the hydraulic coupling is attained without any orientation adjustment to the stinger 125 due to the noted circumferential nature of the passage 130.

In other embodiments, the port 160, rather than the passage 130, may be of a circumferential nature. Alternatively, both the port 160 and the passage 130 may be circumferential. Where circumferential configurations are utilized, so too may multiple hydraulic lines be employed. For example, multiple hydraulic lines may be run through the main body of the stinger 125 to terminate at a circumferential passage 130, or through the main body of the tubular 150 where a circumferential port 160 is utilized. Perhaps more importantly however, so long as at least one of the passage 130 or the port 160 is circumferential, the need to ensure a particular radial orientation between the stinger 125 and tubular 150 is eliminated. Indeed, the configurations detailed hereinabove, utilizing an interlocking stinger 125 and tubular 150 assembly with sliding sleeves 300, 155, avoid the likelihood of damaged hydraulic terminations during coupling. By the same token, the use of a circumferential passage 130 and/or port 160 substantially avoids the possibility of misalignment in coupling of the hydraulics. Thus, the possibility of attaining a hydraulically malfunctioning segmented assembly 100 due to improper downhole mating is virtually eliminated.

Referring now to FIG. 5A, an enlarged sectional view of the upper completion stinger 125 is shown in greater detail. In this view, the stinger line 135 and passage 130 are shown through the body of the stinger 125, leaving the main central channel 110 available, for example, for production fluids. The above noted collets 140 are shown making up the terminal end of the stinger 125, often referred to as a mule shoe 500. Perhaps most notably, however, a realistic depiction of the stinger sliding sleeve 300 is shown. This sleeve 300 is similar to the sliding sleeve 155 of the lower tubular 150 of FIG. 1. However, in the case of the stinger 125, the sleeve 300 is configured as a collar about the main body of the stinger 125 as opposed to a more internal feature. Thus, the stinger sleeve 300 is positioned to sealingly cover the outwardly oriented passage 130. In one embodiment, a shear pin is provided through the stinger sleeve 300 and into the main body of the stinger 125 to prevent unintended shifting of the sleeve 300 before coupling to the tubular 150 of FIG. 5B.

Referring now to FIG. 5B, an enlarged sectional view of the lower completion tubular 150 is shown in greater detail. This view is similar to that of FIG. 1, but with the stinger 125 removed. Therefore, the internal sleeve 155 is located at a more uphole location and covering the port 160. In this view, a collet 550 is shown associated with the main body of the tubular 150 and configured for retaining the sleeve 155 in place. Similar to the shear pin for the stinger sleeve 300 of FIG. 5A as noted above, the collet 550 may be employed to help ensure that the sleeve 155 of the tubular 150 remains in place, sealingly covering the port 160, until coupling with the stinger 125 is achieved.

In the embodiment of FIG. 5B, a scraper ring 575 is incorporated into the sleeve 155 as an aid in dislodging any debris which may have built up within the central channel 110. For example, recall that the lower completion tubular 150 may be installed or ‘hung’ in a manner open to the well 280, perhaps far in advance of deployment of the stinger 125 (and say, associated production tubing 210 (see FIGS. 2 and 5A)). Thus, the scraper ring 575 may be provided to address any buildup during such interim at the inner wall of the tubular 150 defining the channel 110, thereby allowing the noted downward shift of the sleeve 155 during coupling with the stinger 125 of FIG. 5A.

Embodiments detailed hereinabove describe a lower completion tubular 150 with an internal sleeve 155 for sealing an internally oriented port 160 and an upper completion stinger 125 with an external sleeve 300 for sealing an externally oriented passage 130. However, such orientations are relative. For example, an upper completion may utilize an externally oriented sleeve and port for coupling to an internally oriented sleeve and port for a lower completion while still falling within the scope of embodiments detailed herein.

Embodiments detailed above also focus on sleeves 300, 155 which are mechanically shifted. However in other embodiments shifting may be electrically or hydraulically aided. Furthermore, in another alternate embodiment, the sleeves 300, 155 may be configured such that rotational positioning is determinative of port 160 or passage 130 sealing, as opposed to the shifting of lateral positioning.

Referring now to FIG. 6, a flow-chart is shown summarizing an embodiment of installing downhole completions equipped with a hydraulic coupling assembly. The first portion of the assembly, the lower completion tubular, is installed as indicated at 620. This portion includes hydraulics which are sealingly covered by a sleeve as are hydraulics of the next portion of the assembly, the upper completion stinger, which is deployed as indicated at 640. Thus, hydraulic lines for the completions remain sealed off during installation operations. Indeed, as indicated at 660, these sealings are maintained even as the stinger and tubular are initially connected to one another. However, as noted at 680, the hydraulics of these separate completions are eventually coupled by shifting of the sleeves. Nevertheless, this occurs following the beginning of the connecting of the separate completions. Therefore, the integrity of the hydraulics of each completion is maintained throughout the installation process.

Embodiments described hereinabove include downhole tubular accommodating hydraulic lines that may be coupled together in a timely manner. At the same time the likelihood of damaging the couplings during installation is reduced. Thus, less and expense may be devoted to the installation and coupling that accompanies many downhole hydraulically equipped tubular completions. Furthermore, the odds of improper catastrophic installation in terms of hydraulics is virtually eliminated where embodiments of hydraulic coupling tools and techniques are utilized as detailed herein.

The preceding description has been presented with reference to presently preferred embodiments. Persons skilled in the art and technology to which these embodiments pertain will appreciate that alterations and changes in the described structures and methods of operation may be practiced without meaningfully departing from the principle, and scope of these embodiments. For example, installation of completions as detailed herein is described with reference to hydraulics that are utilized in conjunction with production operations. However, such hydraulics may be employed for actuation of downhole tools coupled to the lower completion or any number of alternate hydraulically supported applications. Regardless, the foregoing description should not be read as pertaining only to the precise structures described and shown in the accompanying drawings, but rather should be read as consistent with and as support for the following claims, which are to have their fullest and fairest scope. 

1. A downhole hydraulic completions assembly comprising: an upper completion stinger with a hydraulic stinger line therethrough, the stinger line terminating at a passage isolated by a slidable stinger sleeve relative a main body of said stinger; and a lower completion tubular with a hydraulic tubular line therethrough, the tubular line terminating at a port isolated by a slidable tubular sleeve relative a main body of said tubular, the passage and the port for hydraulic coupling therebetween upon physical coupling of said stinger to said tubular.
 2. The assembly of claim 1 wherein the physical coupling provides shifting of the sleeves to expose the passage to the port.
 3. The assembly of claim 1 wherein said upper completion stinger further comprises a mule shoe with collets for interlocking with a surface of the tubular sleeve.
 4. The assembly of claim 1 wherein at least one of said passage and said port is of a circumferential configuration.
 5. The assembly of claim 4 wherein the stinger line is a first hydraulic line of said stinger, the circumferential passage configured to accommodate a second hydraulic line of said stinger.
 6. The assembly of claim 4 wherein the tubular line is a first hydraulic line of said tubular, the circumferential port configured to accommodate a second hydraulic line of said tubular.
 7. The assembly of claim 1 wherein the stinger sleeve is disposed about the main body of said stinger and the tubular sleeve is disposed adjacent an inner wall of said tubular.
 8. The assembly of claim 7 wherein the tubular sleeve is equipped with a scraper ring for interfacing the inner wall.
 9. The assembly of claim 1 wherein the stinger sleeve is interiorly disposed relative the main body of said stinger and the tubular sleeve is disposed about a main body of said tubular.
 10. A hydraulically outfitted downhole completions system comprising: upper completions disposed in a cased portion of a well, said upper completions having a stinger with a hydraulic line therethrough and terminating at a passage isolated by a slidable sleeve relative a main body of the stinger; and lower completions disposed in an at least partially open portion of the well adjacent the cased portion, said lower completions having a tubular coupling to the stinger and equipped with a hydraulic line therethrough, the line of the tubular terminating at a port isolated by a slidable sleeve relative a main body of the tubular.
 11. The system of claim 10 wherein the coupling aligns the passage and the port for hydraulic communication there between.
 12. The system of claim 11 wherein the coupling provides shifting of the sleeves to expose the passage to the port for the communication.
 13. The system of claim 10 wherein said upper completions further comprises production tubing coupled to the stinger to provide a conduit for production fluid flow to a surface of an oilfield adjacent the well.
 14. The system of claim 13 wherein said lower completions further comprises production intake equipment in fluid communication with the hydraulic line through the tubular, the system further comprising chemical injection equipment disposed at the oilfield surface and hydraulically coupled to the hydraulic line through the tubular via the hydraulic line through the stinger.
 15. A method comprising: installing a lower completion tubular in a well, the tubular accommodating a hydraulic line through a main body thereof and a slidable sleeve for sealing off a port at a terminal end of the line; and deploying an upper completion stinger to a location adjacently uphole of the tubular, the stinger accommodating a hydraulic line through a main body thereof and a slidable sleeve for sealing off a passage at a terminal end of the line through the stinger.
 16. The method of claim 15 further comprising: initiating coupling of the stinger to the tubular; and maintaining the sealing with the sleeves during said initiating.
 17. The method of claim 16 further comprising: aligning the passage with the port; and shifting the sleeves away from the passage and the port during said aligning to allow for hydraulic coupling between the lines.
 18. The method of claim 17 further comprising performing a hydraulically actuated application in the well through the lines.
 19. The method of claim 18 wherein the application is one of chemical injection and operation of a hydraulically actuatable downhole tool.
 20. The method of claim 17 further comprising: decoupling the stinger from the tubular: resealing the passage and the port with the sleeves during the decoupling; and withdrawing the stinger from the well. 